For drilling an oil well it is necessary to use a fluid (traditionally known as mud) which can be water-based or oil-based or a gas in order to perform multiple functions. This fluid must, among other things, counter the pressure of the drilling fluids cool and lubricate the drill bit, carry the drilled cuttings to the surface for being separated and recycled, previous conditioning, for re-entering same to the well itself.
During the drilling operations several formations are traversed through different formations (shale, sand, sandy shale, limestone, marl, chalky shales, etc.) before reaching the formation containing hydrocarbons which must be taken to market. Usually the deposits where the hydrocarbons are located consist of carbonate rocks, sand and/or sandy shale, which by virtue of its permeability may allow such hydrocarbons to flow in a natural way by taking advantage of the existing pressures in deposits or well, released deposits requiring the use of secondary recovery techniques (gas lift, rod pump, electro centrifugal pump, etc.). Invariably, the hydrocarbons flow through the porous medium will depend greatly on both, insoluble particles of traditional drilling fluids that may have invaded these areas, causing, among other reasons, the clogging of the pores of the formation, and thus the reduction in the hydrocarbon production. Permeability is the ease with which the pores of the formation may allow for the free flow of fluid through them, which will depend greatly on both, that the pores are communicated with each other and that there are no foreign particles in the formation preventing or blocking the passage of fluids through it, this process of invasion or blocking of the pores of the formation is traditionally known as damage to the productive formation, same that is caused by the fluids used during the drilling, completing or repairing operations of oil wells.
The traditional solids-containing drilling fluids are generally insoluble solids in water and oil, same that, at the time of drilling, invade the productive formation causing clogging of the pores of the formation thereby reducing its permeability. The chemical nature of these solids (usually weighting agents as barite, ilmenite, galena, iron oxide, etc.) prevents them from being dissolved by the traditional treatment with 15% HCl, this causing irreversible damage to the permeability of the formation. Additionally, certain types of surfactants (preferably and for example emulsifiers, moisturizers and reducers of surface and interfacial strength) used in the formulation of drilling fluids, may interact with the formation fluids (water or crude oil) creating emulsions that are difficult to remove, as on one side, the created emulsions have high viscosities (characteristic of emulsions) and on the other, change the formation's wettability which prevents or restricts the flow of hydrocarbons through the pores of the productive formation.
In order to solve the concerns related to damages to the productive formation, fluids formulated based on solids-free heavy brines have been used, which have the advantage of not requiring insoluble solids (such as barite, calcium carbonate, iron oxide, galena, etc.) to increase the density required by high-pressure/high-temperature wells in order to control formation pressures, this type of fluid increases its density by dissolving salts or mixtures thereof (NaCl, KCl, CaCl2, CaBr2, ZnBr2, NaHC03, NaBr, KHCO3, NaHCO3, NH4Cl, etc.) in water, such that there are no insoluble solids (in suspension) which may, during the drilling of the productive area, invade the formation with the consequent plugging and reduction of the well's permeability and production. Table 1 shows the achievable density ranges with the most commonly used brine systems.
TABLE 1Brines used as completing and repairing fluids.TYPE OF BRINEDENSITY RANGEKCl0.99-1.16 g/cm3NaCl0.99-1.20 g/cm3NaHCO20.99-1.20 g/cm3CaCl20.99-1.39 g/cm3KHCO20.99-1.59 g/cm3NaBr0.99-1.52 g/cm3NaCl—NaBr1.20-1.52 g/cm3CaCl2—CaBr21.39-1.81 g/cm3CaBr20.99-1.83 g/cm3CaCl2—CaBr2—ZnBr21.81-2.35 g/cm3CaBr2—ZnBr21.70-2.52 g/cm3
While this type of drilling fluid systems do not contain solids in suspension to increase the density, it is also true that they require additives in order to provide the required physicochemical properties for the drilling fluid to comply with its functions for drilling the productive area, i.e., mainly, viscosifying agents, reducers of filtrate loss (commonly called filtrate reducers), alkalizing agents, bridging agents, heat stabilizers, corrosion inhibitors, clay hydration inhibitors, acid gas sequestrants, corrosion inhibitors, etc.) are required, same that must be embedded in the solids-free brines.
Thus, in the prior art there are different systems for solids-free brines wherein the mentioned additives have been embedded. However, such systems face two major problems:
A) One is that when the required density is greater than 1.40 g/cc and there is the presence of divalent metal containing salts, the viscosifying polymers traditionally used have problems for being hydrated in water, this is mainly because most of the water is associated with salt and there is not enough free water for the polymer to be acceptable hydrated, requiring in some cases, the increasing of mixing times, combined with high shear speeds and/or supplying heat (temperature increases) to achieve viscosifying the brine and/or embed some filtrate reducer polymer, and
B) Two, that the polymers traditionally used to increase the viscosity of the brine and/or to reduce the loss by filtration cannot withstand high temperatures (over 150° C. and 200° C.) required for the formations to be drilled, this arising from the fact that the deposits that are located at shallow depths, practically, no longer exist, and today have to drill ever deeper thereby increasing the downhole temperature, considering the geothermal gradient of the area.
In the prior art, there are different natural polymers that are used to viscosify brines, these are, among others, xanthan gum (biopolymer) and hydroxyethyl cellulose (HEC, polysaccharide)), however, both polymers have some problems for viscosifying heavy brines. HEC is a typical viscosifier used to viscosify brines, however, it requires heating for reaching the viscosities required when the densities are greater than 1.45 g/cc, further, HEC has stability problems when the downhole temperatures exceed 130 C. Similar behavior occurs when using Xanthan Gum for viscosifying brines containing divalent cations and especially when densities are greater than 1.45 g/cc (Patent WO 88/02/02434).
Further, there are other synthetic polymers in the prior art that have been used and proposed for viscosifying heavy brines, U.S. Pat. No. 4,490,261 discloses and claims a fluid for oil well drilling, which uses a polymer or N-heterocyclic copolymer such as poly vinyl pyridine in order to increase the viscosity at temperatures above 300° F. (148.9° C.), of a fluid containing a high titer of acid salts (zinc bromide) in order to be used for the drilling of the productive areas, claiming that said invention does not contain other polymeric thickeners such as starch, sodium carboxymethylcellulose, and modified polyacrylate.
U.S. Pat. No. 5,480,863, discloses and claims a composition comprising brine containing zinc bromide, a viscosifier acrylamide copolymer and 2-acrylamide-2-sodium methylpropanesulphonate and a dimethyl benzyl ammonium chloride surfactant. Wherein the copolymer, which is the only composition viscosifier, shows that same may be able to viscosify the heavy brines with densities up to 19.2 lb/gal (2.30 g/cc) but they require heating to develop their properties and their thermal resistance is limited to a range of 80 to 300° F. (26.66 to 148.88° C.).
It should be noted, considering the existence of high porosity productive formations, naturally fractured with cracks, fissures, caverns and/or microfractures, it is necessary to embed the drilling fluid of the present invention with bridging materials that help in controlling fluid losses into the formation, this, in order to minimize the invasion of the drilling fluid that could cause any damage to the permeability through any of the above listed mechanisms. These bridging agents consisting mainly of solid particles (CaCO3, MgCO3, etc.) that could subsequently be removed by the treatment with HCl or HF and which further have a particle size distribution appropriate to the size of the pore gorge and/or size of the fracture, fissure or cavern, the maximum size being of ⅓ the size of the pore gorge in order to contain the fluid flow into the productive formation.